In the art of drilling wells to tap subterranean deposits of fluids such as oil and/or gas, especially when drilling by the rotary method employing a rotary bit and drill stem, a drilling fluid, usually a compounded fluid made to predetermined physical and chemical properties, is circulated to the bottom of the bore hole, out through openings in the bit at the bottom of the bore hole, and then back up said bore hole to the surface by passage through the annular space between said drill stem and the wall of said bore hole (or between said drill stem and the wall of the casing where casing has been put in place).
The drilling fluid preferably acts as a liquid medium of controlled viscosity for removing cuttings from the bore hole; it should prevent excessive amounts of fluid from flowing from the bore hole into surrounding formations by depositing on the wall of the hole a thin but substantially impervious filter cake; it preferably possesses a gel structure of sufficient strength to hold solids in suspension, particularly during any time the fluid is not circulating; and it should serve as a weighting material exerting sufficient pressure to counterbalance any pressure exerted by water, gas, oil, or other fluid from a penetrated structure and to prevent caving or other intrusion into the drill hole.
These preferred characteristics have been provided in the past by employing both aqueous or water base and non-aqueous or oil base drilling fluids. The aqueous drilling fluids normally comprise water and finely divided inorganic materials such as various types of clays and clayey materials, and may also contain weighting materials, all suspended in the water. The non-aqueous or oil base drilling fluids normally comprise a non-aqueous liquid such as crude oil or a petrolum distillate, and a weighting material which can be a clay or other suitable material. In addition to aqueous and non-aqueous drilling fluids as defined above, emulsion-type drilling fluids are often used. These emulsion drilling fluids normally comprise a substantially water-insoluble liquid such as oil, a finely divided inorganic material such as clay, and water, together with a suitable dispersing or emulsifying agent. The two types of emulsion drilling fluids are the oil-in-water emulsion type, sometimes referred to as water base emulsion type, and the water-in-oil emulsion type, sometimes referred to as oil base emulsion type. In the latter, oil forms the continuous phase of the emulsion, and in the former, water or brine forms the continuous phase of the emulsion.
Various clays can be used in the various types of drilling fluids, but the most common are bentonite, a water-swelling clay preferred for use in fresh water fluids, and attapulgite, a non-swelling clay used in salt water fluids.
In the drilling of wells there are major difficulties caused by natural formations penetrated. One of these difficulties is the encountering of certain formation, such as gypsum, which will "cut" the drilling mud so that the clay particles are flocculated and the viscosity becomes too high. In such instances there is danger of the drill pipe twisting in half, or of gas cutting of the mud, or of a blowout occurring due to the cutting of the mud. Another difficulty is the encountering of formations known as heaving shale. A heaving shale absorbs water from the drilling mud and by a caving or disintegrating action common to clay and shale, or by a swelling action common to bentonite materials, the well hole is closed around the drill string, choking off the circulation of drilling mud and often seizing the drill string so that it cannot be rotated or twists in half. Another difficulty which is frequently encountered in deeper wells is gelation and/or thickening of the drilling mud due to the higher temperatures encountered in said deeper wells. This tendency to gel or thicken is most pronounced in muds containing water-swelling clays such as bentonite. In such instances the drilling mud actually gels and/or thickens, greatly increasing the pump pressures required for circulating the drilling mud. In severe cases it becomes practically impossible to properly circulate the mud. Furthermore, said high temperature gelation is frequently aggravated by the presence of contaminants such as gypsum, salt, cement, etc. in the drilling mud. Thus, another preferred characteristic for drilling muds is that they be characterized by stability at the higher temperatures encountered in deeper wells and in the presence of contaminants.
Various drilling fluid additives have been developed to prevent or remedy such problems. Hoeppel discloses in U.S. Pat. No. 2,605,221 (1948) the control of the viscosity and gel strength of drilling fluids by the addition of a compound the cation of which is a normally flocculating heavy-metal ion such as manganese, nickel or tin, and a non-acid-forming normally deflocculating peptizing compound such as a tannate or humate. Sulfoalkylated tannins are not disclosed, nor are mixtures of lignite and sulfoalkylated tannins. Floyd and Shell disclose in U.S. Pat. No. 3,479,287 (1969) drilling fluid additives containing a first agent of a sulfoalkylated tannin and a second agent selected from water soluble inorganic compounds of chromium, aluminum, vanadium, titanium, zinc and manganese, said agents being added to control at least one of the properties yield point, gel strength and water loss of a drilling fluid. One such additive, a physical blend of sulfomethylated quebracho and sodium dichromate dihydrate (Na.sub.2 CrO.sub.3.2H.sub.2 O), has been marketed successfully as Desco.RTM. drilling mud thinner by Drilling Specialties Company, Bartlesville, Okla. 74004. However, due to the rising costs of quebracho and the sulfoalkylation process and the fact that quebracho is an essentially nonrenewable resource obtained from a single country (Argentina), it is desirable to find equivalent raw materials which are more effective and/or less costly and are readily available in quantity. Furthermore, chromates are on the hazardous substance list of the Environmental Protection Agency. Several countries have prohibited the use of chromium compounds in drilling muds. Other areas, notably the Canadian Arctic and California, have stringent rules as to the use and disposal of drilling muds containing chromium compounds. Therefore, it is desirable to develop additives containing equally effective and economical materials which are non-hazardous and/or not subject to restrictive regulations.
The apparent viscosity or resistance to flow of drilling muds is the result of two properties, plastic viscosity and yield point. Each of these two properties represents a different source of resistance to flow. Plastic viscosity is a property related to the concentration of solids in the fluid, whereas yield point is a property related to the interparticle forces. Gel strength, on the other hand, is a property that denotes the thixotropy of mud at rest. The yield point, gel strength, and, in turn, the apparent viscosity of the mud, commonly are controlled by chemical treatment with materials such as complex phosphates, alkalies, mined lignites, plant tannins, and modified lignosulfonates.
Reducing the viscosity of a drilling fluid suggests a thinning action. Materials used to accomplish this thinning action are called "thinners" and in particular "mud thinners." This thinning action can result from reducing the plastic viscosity, the yield point, the rate and degree of gelation, or a combination of any of the three effects. It is usually very difficult to vary any one of the effects without affecting either or both of the others.
Thinners in drilling muds are thought to act to oppose the development of gel structure without substantially altering the hydration of the clays. Thinners generally have, as a common characteristic, a large negative ion. These large anions are thought to be absorbed on the edge surfaces of the clay particles and reduce attractive forces between the particles, thereby decreasing the tendency of the particles to form a gel structure. Thinners usually have a small effect on the plastic viscosity of water-base drilling fluids.
Plant tannins are effective thinners of freshwater-base drilling fluids as well as those treated or contaminated mildly with salt, cement, lime, and gypsum. Quebracho continues to be the most widely used member of this group, because it is generally more versatile and economical to use.
Lignitic materials, which are resistant to salt and cement contaminations, effectively emulsify oil in high percentages and are especially stable in drilling muds at high temperatures. Lignitic materials are becoming increasingly important to impart high-temperature stability to drilling muds thinned with lignosulfonates.
Lignosulfonate thinners are made from the spent cooking-liquor by-product of the manufacture of cellulose pulp by the sulfite process. Basic calcium lignosulfonates are precipitated from liquor. Calcium lignosulfonate is useful as a thinner for lime-treated muds and saturated saltwater-emulsion muds. Ferrochrome lignosulfonate is used as a thinner for "inhibited" drilling muds. It performs effectively in drilling muds containing salt or calcium sulfate, not only controlling the rheological properties, but also reducing the filtrate loss.
Contaminants bring about undesirable increases in viscosities, gel strengths, and filtrate losses in water-base drilling fluids. The typical contaminants, listed in order of decreasing frequency, are cement, salt, anhydrite, hydrochloric acid, and hydrogen sulfide. One method of counteracting the effects of such contaminants is to treat the mud with a chemical that compensates or overcomes the detrimental effects caused by the contaminant; eg, when drilling mud is contaminated mildly with salt, treat with an alkalized tannin, lignitic material, or ferrochrome lignosulfonate.